Techniques for determining an angular offset between two objects

ABSTRACT

An angular offset apparatus for determining an angular offset, or scribe line offset (SLO), of two objects within a drilling environment. The angular offset apparatus may include a sensing component and a target component located at various locations within the drilling environment. The sensing component may implement one or more sensors configured to collect data associated with the target component and the drilling environment to determine the SLO between the two objects. The angular offset apparatus, along with the calculated SLO, is designed to ensure accuracy and safety during drilling operations.

This application claims priority to U.S. application Ser. No.62/341,998, filed on May 26, 2016, entitled “System and Method forDetermining an Angular Offset Between Two Objects,” and U.S. applicationSer. No. 62/487,473, filed on Apr. 19, 2017, entitled “Techniques forDetermining an Angular Offset Between Two Objects,” the contents ofwhich are incorporated herein by reference. In addition, the contents ofU.S. application Ser. No. 62/284,406, filed on Sep. 29, 2015, entitled“ACCU-Scribe, being an improvement in drilling technology,” are alsoincorporated herein by reference.

BACKGROUND

A variety of techniques are utilized in the oil and gas field whencreating a new borehole or well. Drilling techniques may vary dependingon the type of formation, the location of the rig, the product to beextracted, etc. During formation of the borehole, a well-bore plan, orother previously designed plan for drilling the borehole, is implementedvia a computing system or human operations, in conjunction with theborehole assembly, to ensure accurate drilling measurements. Accuratedrilling measurements ensure that the reservoir of product, such as oiland/or gas, is reached during the drilling process.

The borehole assembly may include a directional tool, such as aMeasurement While Drilling (MWD) tool, often having internal computersthat use accelerometers and magnetometers to determine the direction ofthe tool heading, otherwise referred to as the high-side of the tool. Adownhole tool, such as a drilling motor, mud motor, or any othersuitable downhole tool, may also be utilized. The downhole tool mayinclude a bent housing located at a bottom end of the tool, such as thebottom end of the drilling motor.

While the downhole tool does not have computer technology within itself,it may be attached to the directional tool during drilling operations.The directional tool may operate according to the well-bore plan,thereby controlling the direction of the downhole tool according to thewell-bore plan. When the directional tool and downhole tool areattached, the heading of the directional tool and the heading of thedownhole tool may be different. The heading of the various drillingtools may be indicated by a high-side marking, or other indicator, thatis marked on the exterior of the drilling tool.

The offset between the directional tool heading and the downhole toolheading, referred to as the angular offset or scribe line offset (SLO),needs to be accounted for and provided to the computing device, oremployee, controlling the well-bore plan to ensure accurate drilling. Ifthe SLO is not accounted for, the drilling measurements may haveinaccuracies that can lead to drilling issues and mistakes, such asmissing the product reservoir, leading to costly time delays and evenabandonment of the borehole.

Conventional techniques for calculating the SLO are often left to humanapproximations. For example, conventional techniques include a rigemployee using line of sight to roughly estimate the SLO. An employeemay stand at the base of the downhole tool, beneath a directional toolsuspended above, and estimate the SLO between a high-side markingindicating the heading of the directional tool and a high-side markingindicating the heading of the downhole tool. This method of calculatingthe SLO leaves room for significant human error as little accuracy canbe ensured using human estimations alone. For example, a drillingemployee may be standing at a distance of seventy feet, or longer, belowthe high-side marking of the directional tool, making it very difficultto visually estimate the offset between the heading of the directionaltool and the heading of the downhole tool. Mistakes in thedirectional-drilling measurements can lead to problems drilling thewellbore, and even abandonment, resulting in costly and time-consumingsetbacks.

In addition, safety issues can also be of concern. The drillingenvironment can be filled with many hazardous conditions related todrilling machinery and operations. For example, requiring that anemployee stand below a suspended MWD during drilling operations can leadto increased risk of human injury.

BRIEF DESCRIPTION OF THE DRAWINGS

The detailed description is set forth with reference to the accompanyingfigures. In the figures, the left-most digit(s) of a reference numberidentifies the figure in which the reference number first appears. Theuse of the same reference numbers in different figures indicates similaror identical items.

FIG. 1 illustrates an example drilling rig implementing an angularoffset apparatus according to some examples.

FIG. 2 illustrates a first side view of a sensing component of anangular offset apparatus according to some examples.

FIG. 3 illustrates a first perspective view of the sensing component ofFIG. 2.

FIG. 4A illustrates a second perspective view of the sensing componentof FIG. 2 in an unlatched configuration.

FIG. 4B illustrates a third perspective view of the sensing component ofFIG. 2 in a latched configuration.

FIG. 5A illustrates an example drilling assembly implementing a targetcomponent of an angular offset apparatus according to some examples.

FIG. 5B illustrates a perspective view of the target component of FIG.5A.

FIG. 5C illustrates a perspective view of the bottom surface of thetarget component of FIG. 5A.

FIG. 6 illustrates a perspective view of an example drilling assemblyimplementing another embodiment of an angular offset apparatus accordingto some examples.

FIG. 7 illustrates an example architecture of the control system of theangular offset apparatus of FIG. 1.

FIG. 8A illustrates an example graphical user interface implemented withthe example architecture of FIG. 7.

FIG. 8B illustrates another example graphical user interface implementedwith the example architecture of FIG. 7.

FIG. 8C illustrates another example graphical user interface implementedwith the example architecture of FIG. 7.

FIG. 9 illustrates an example flow diagram showing an illustrativeprocess for determining a scribe line offset (SLO) using the angularoffset apparatus of FIG. 1.

FIG. 10 illustrates a side view of another embodiment of a sensingcomponent of an angular offset apparatus according to some examples.

DETAILED DESCRIPTION

The present disclosure is directed to techniques for determining anangular offset, or scribe line offset (SLO), for use in drilling awellbore during oil and gas operations. In some examples, a sensingcomponent and a target component may be implemented for use incalculating the SLO for a particular oil and gas rig. For example, thesensing component may be placed adjacent to a first drilling tool of therig and the target component may be placed adjacent to a second drillingtool. The sensing component and the target component may be placedopposite each other within the rig environment. For example, the sensingcomponent may be placed adjacent to the rig floor, adjacent to adownhole tool, and the target component may be suspended above the rigfloor, adjacent to a directional tool. Each tool may also include ahigh-side marking which indicates the high-side, or heading, of thetool.

The sensing component may be implemented to collect various dataassociated with the heading, indicated by the high-side marking, of thedirectional tool or downhole tool. For example, the sensing componentmay be located adjacent to the high-side marking of the downhole tooland collect image data of the target component, located adjacent to thehigh-side marking of the directional tool. The sensing component maycollect data related to the target component to calculate the SLObetween the high-side marking of the downhole tool and the high-sidemarking of the directional tool. The calculated SLO may then be providedto the rig computer(s), such as the directional tool computer(s), toensure accurate and timely drilling measurements are used to plan thetrajectory of drilling the wellbore. In some implementations, thesensing component and target component may be placed on the drillingtools and in the rig environment throughout the course of drillingoperations (e.g. during the laying down or picking up of the boreholeassembly), resulting in the ability to have at or near real-time SLOcalculations, further reducing the risk of drilling complications due toSLO errors and the need for drilling employees to be on site forSLO-related operations.

The sensing component may implement one or more sensors designed tocollect data related to imaging, local positioning, heat, light (i.e.,including electromagnetic radiation of any frequency), etc. The sensingcomponent may be securely attached adjacent to the high-side marking ofa drilling tool, which indicates the heading of the tool, and may belocated opposite the target component. Exact placement of the sensingcomponent may vary depending on the weight restrictions and drillingrequirements of the rig. For example, the sensing component may besecurely attached adjacent to the high-side marking of a downhole toolin some examples or may be securely attached adjacent to the high-sidemarking of a drilling tool in other examples. In additional examples,the sensing component may be placed adjacent to a top-drive locatedabove both the drilling tool and the directional tool. The sensingcomponent may also implement a microcontroller, a wireless communicationdevice, and an energy source, among other components, to provide thesensing data to an external device for processing. Alternatively, thesensing component may process the sensing data locally.

The target component may implement various marking and/or indicatorcomponents, as well as local positioning sensors. For example, thetarget component may implement an LED array that includes one or moremarkings indicating pre-determined increments, as well as an indicatorthat is aligned with a drilling tool high-side marking. As describedabove with respect to the sensing component, exact placement of thetarget component may vary with each rig and multiple example placementswill be described herein.

In some examples, the sensing component may be located at a downholetool near the rig floor and the target component may be located at adirectional tool that is suspended above the rig floor. Both the sensingcomponent and the target component may be located at external high-sidemarkings of the downhole tool and the directional tool, respectively.The sensing component may implement one or more imaging sensors, such ascameras configured to capture stationary or rotational image data orvideo data, configured to gather image data of the target component. Theimage data may then be transmitted to an external computing system todetermine the SLO.

In other examples, the sensing component may implement one or moresensors configured to detect light, including electromagnetic radiationof any frequency, emitted from a target component. For instance, thetarget component may implement one or more light emitting components,such as a laser, where at least one of the light emitting components maybe aligned, either manually or through an automated process, with theexternal high-side marking of a directional tool. The light detectingsensor(s) of the sensing component may be configured to detect lightfrom the light emitting component(s) of the target component todetermine the SLO.

In still further examples, the sensing component and the targetcomponent may be implemented as part of a local positioning system fordetermining the SLO of a rig environment. In this example, the sensingcomponent and the target component may each implement one or moreantennas or beacons that are placed adjacent to the high-side marking ofthe directional tool and the high-side marking of the downhole tool. Thelocal positioning system may use beacon data to calculate thelocations/positions of the high-sides of the directional tool and thedownhole tool using any number of methods such as triangulation,trilateration, multilaterion, etc. The location/position data of thehigh-sides can then be transmitted to a computing device and used tocalculate the SLO.

The techniques, systems, and devices described herein improve the safetyand accuracy of oil and gas drilling operations, such as during thepicking up and laying down of the borehole assembly. For example, thesystems and methods for determining the angular offset between twoobjects described herein helps ensure that an accurate SLO can becalculated for directional drilling operations. In addition, in someexamples, real-time calculations may be achieved. In contrast to thetraditional methods of calculating an SLO using visual estimationsalone, the systems and methods described below utilize sensing andtarget components, along with computer technologies, to calculate aprecise SLO that minimizes the margin of error associated with visualestimations.

In addition to the oil and gas related implementations described above,the techniques, systems, and examples described herein may beimplemented in technology areas related to type-fitting, welding,construction, architecture, surveying and dimensional analysis, mining,natural resource wells, pipeline fittings, safety designs, etc.

These and other examples are described below in more detail withreference to the representative architecture illustrated in theaccompanying figures.

FIG. 1 illustrates an example drilling rig environment 100 implementingan angular offset apparatus 102 according to some examples. In thisexample, the angular offset apparatus 102 includes a sensing component104, a target component 106, and a computing device 108.

In some examples, the sensing component 104 is placed adjacent to thehigh-side marking of a downhole tool 116. The sensing component 104 mayimplement one or more sensors configured to collect data related toimaging, local positioning, heat, light (i.e., including electromagneticradiation of any frequency), etc. For instance, in the illustratedexample, the sensing component 104 implements two sensors 110, 112 thatare mounted on the exterior of the downhole tool 116. However, in otherexamples, any number of sensors may be implemented in variousconfigurations.

In some examples, at least one of the sensors 110, 112 may be alignedwith a high-side marking of the downhole tool 116 to serve as an originpoint for determining the scribe line offset (SLO). In other examples,the sensors 110, 112 may not be aligned with the high-side marking ofthe downhole tool 116 and may be placed adjacent to other locationswithin the rig environment 100. In these instances, the sensingcomponent 104 may include an indicator mark that indicates the locationof the high-side marking of the downhole tool 116. The sensing componentmay also include markings that allow for the offset between the sensors110, 112 and the indicator mark aligned with the high-side marking ofthe downhole tool 116 to be calculated and used when determining theSLO.

In further examples, the target component 106 may be placed adjacent tothe high-side marking of a directional tool 114. The target componentmay include one or more indicators placed adjacent to the high-sidemarking of the directional tool 114 that are visible and able to bedetected by the sensors 110, 112 of the sensing component 104. Forexample, the target component 106 may include a collar with linedmarkings, such as LED markings, each spaced a pre-determined distanceapart. At least one of the lined markings may be unique to indicate thehigh-side marking of the directional tool 114. For instance, the uniquelined marking may include a perpendicular hash mark, or some othermarking to distinguish the unique lined marking from the rest of thelined markings.

In some examples, the sensors 110, 112 may include imaging sensorsconfigured to collect image data of the target component 106. Inparticular, sensors 110, 112 may take stationary photos from each sideof the downhole tool 116. In some examples, the sensors 110, 112 mayalso rotate about the downhole tool 116 to capture 360-degree image dataof the target component 106 and rig environment 100. The captured imagedata may be transmitted via wireless or wired technology for processingat the computing device 108. For example, the captured image data may betransmitted to a cloud-based system where the image data can be storedand/or computations performed. During processing, image rendering may beperformed, an aspect ratio may be set, combined images may be generated,image recognition techniques may be applied, etc. For example, thedimensions of multiple images may be compared, altered, or combined. Forinstance, images from each of the sensors 110, 112, showing imagescaptured from each side of the downhole tool 116, may be combined toshow a 360-degree view of the downhole tool 116 and target component106. The combined image rendered, or the individual images, may then beused to determine the location of the high-side marking of thedirectional tool 114.

Using calculations pre-programmed into the computing device 108, thecomputing device 108 can determine the angular offset between thelocation of the two high-side markings of the directional tool 114 andthe downhole tool 116, otherwise referred to as the scribe line offset(SLO). The use of imaging data and computerized calculations helpssignificantly improve the accuracy of the SLO value, as opposed toconventional techniques that utilize line of sight alone. In addition,the placement of the sensing component 104 and the target component 106within the rig environment can enable the real-time calculation of theSLO offsite, decreasing the number of crew members required onsite andimproving the safety of the rig environment 100.

Further, each rendered image may be marked with a unique serial numberand/or other identification information, such as information related tothe equipment in the rig environment 100. Marked images may be storedfor subsequent recall. Identifying and storing each rendered image helpskeep a running log of each image used to calculate each SLO foraccountability and use by the rig crew. In some examples, the renderedimages may be stored in cloud-based storage, servers, or other storageapplications.

In some examples, the placement of the sensing component 104 and thetarget component 106 may vary according to the rig environment, designconsiderations, etc. For example, the target component 106 could bemounted onto a tool located above the directional tool 114, such as atop-drive. In this example, the target component may still be alignedwith a high-side marking of the directional tool 114 while mounted abovethe top-drive. In other examples, the sensing component 104 and targetcomponent 106 may be mobile. For instance, the sensing component 104 andthe target component 106 may be implemented in conjunction with flightcapable instruments, such as drone technology. In further examples, thesensing component 104 may be mounted on the directional tool 114 and thetarget component 106 may be mounted on the downhole tool 116.

In other embodiments, representing variations of the implementationsshown in FIG. 1, an angular offset apparatus may implement a sensingcomponent that includes one or more sensors designed to detect lightfrom a target component, such as from lasers that are included in thetarget component. This embodiment is described in greater detail withrespect to FIG. 6 below. Additional and/or alternative examples includedetecting indicator(s) produced via non-visible light or variousfrequencies of electromagnetic radiation.

In still further embodiments, representing variations of theimplementations shown in FIG. 1, an angular offset apparatus mayimplement a local positioning system. The local positioning system mayimplement one or more beacons or antennas, or other apparatuses capableof collecting and transmitting local positioning data. Each antenna maybe located at the high-side of a drilling tool, such as the directionaltool 114 and the downhole tool 116 illustrated in FIG. 1. In thisembodiment, a grid system is determined and components of the localpositioning system may be placed adjacent to known locations. Forexample, four local positioning components, may be placed adjacent tofour corners of the drilling environment 100, with each of the fourcomponents placed adjacent to a known location. In other examples, anynumber and configuration of local positioning components may beimplemented according to the unique drilling environment.

To calculate the SLO, each beacon or antenna may ping off the knownlocations and collect data, including the time period needed for theping to travel to the local positioning component from each beacon orantenna, the time period needed for the ping to return to each beacon orantenna from the local positioning component, and information regardingwhere each beacon or antenna is located, such as the at the high-sidemarking of a drilling tool to which the antenna or beacon is attached.The collected data may then be provided to the computing device 108 and,utilizing the collected data, the angular offset, or SLO, is determinedby the computing device 108. The SLO may then be accounted for in thewell-bore plan and ultimately provided to the directional tool 114 viathe computing device 108 to be accounted for during drilling operations.

FIG. 2 illustrates a first side view of an example sensing component 200of the angular offset apparatus (e.g., angular offset apparatus 102)described herein. The sensing component 200 is shown placed around theoutside perimeter of a downhole tool 202 used during drillingoperations, including during the picking up or laying down of theborehole assembly, which includes tooling such as a drilling motor ormud motor.

In this example, the sensing component 200 implements two imagingsensors 204, 206 configured to capture image content and placed adjacentto opposite ends of the downhole tool 202. One of the imaging sensors204, 206, referred to as an origin camera, may be placed adjacent to theexternal high-side marking (not shown) of the downhole tool 202 to helpdetermine an approximate origin location of the imaging sensors 204,206. Knowing the origin location of the imaging sensors 204, 206 helpsdetermine the scribe line offset (SLO) by providing information such asthe location of the high-side marking of the downhole tool 202 (i.e. theorigin of the offset of the rig) as well as helping to set the aspectratio of the image content. In other embodiments, the imaging sensors204, 206 may be placed away from the high-side marking of the downholetool 202. In this embodiment, the offset between the sensors 204, 206 isdetermined and accounted for when calculating the SLO.

In some examples, the image content may include image data, captured bythe imaging sensors 204, 206, showing a marker or indication of thelocation of a second high-side marking of another drilling tool, such asa directional tool, of the bottom hole assembly (BHA). The location ofthe directional tool high-side marking, along with the location of thehigh-side marking of the downhole tool 202, may be used to determine theSLO, sometimes referred to as the angular offset, of the two high-sidemarkings with increased precision and accuracy.

In the illustrated example, the sensing component 200 is shown attachedto the downhole tool 202 at an external high-side marking (not shown).To attach the sensing component 200 to the downhole tool 202, thesensing component 200 implements a mounting mechanism that can belatched and unlatched for attachment and removal, respectfully, of thesensing component 200. The mounting mechanism may implement one or moreattachment fasteners 208, 210, one or more transport mechanisms 212,214, one or more mounting brackets 216, 218, 220, 222, and one or moreconnecting brackets 224, 226. The mounting mechanism helps ensure thatthat sensing component 200 is aligned with the center line of thedownhole drilling 202 when mounted.

In some examples, the attachment fasteners 208, 210 are located on themounting mechanism and configured to secure the components of themounting mechanism in the desired configuration. In this example, theattachment fasteners 208, 210 include a bolt assembly. However, anyfastener meeting the weight and safety requirements of the sensingcomponent 200 and the rig environment may be used.

In addition, the transport mechanisms 212, 214 may allow for a user,such as a rig employee, to transport the sensing component 200 forplacement on the downhole tool 202. For example, the transportmechanisms 212, 214 may include one or more handle grips. The sensingcomponent may be lifted manually by the one or more transport mechanisms212, 214, or via machinery utilizing the transport mechanisms 212, 214,depending on the drilling rig, weight of the sensing component 200,difficulty of placement, and safety considerations. The transportmechanisms 212, 214 may also be configured to allow for rotation ofcomponents of the mounting mechanism, such as the mounting brackets 216,218, 220, 222.

In some instances, the connecting brackets 224, 226 may be located at afirst end and a second end of the transport mechanisms 212, 214. Theconnecting brackets 224, 226 may be opened or closed to allow for theattachment and removal of the sensing component 200. The connectingbrackets 224, 226 may run parallel to the imaging sensors 204, 206 andmay serve as the connecting structure between the two imaging sensors204, 206.

Further, the mounting brackets 216, 218, 220, 222, may include a disc orring that wraps around exterior housings 228, 230, 232, 234 of theimaging sensors 204, 206. The mounting brackets 216, 218, 220, 222 areconfigured to hold the imaging sensors 204, 206 at a fixed location andprevent migration. The mounting brackets 216, 218, 220, 222 may bepermanently fixed to the exterior housings 228, 230, 232, 234 or may bedetachable, allowing for the placement and removal of the imagingsensors 204, 206. In some examples, exterior housings 228, 230, 232, 234may be placed on the external body of the imaging sensors 204, 206 andmay serve as a protective outer housing, or explosion-proof housing.

In addition, while the sensing component 200 illustrated in FIG. 2 isremovable, alternative examples may include a sensing component 200 thatis permanently attached to a drilling tool. Also, the sensing component200 may not implement a mounting mechanism and may be attached to thedownhole tool 202 via alternative attachment means. For example, themounting mechanism may be a separate component, independent of thesensing component 200, that may be attached to the downhole tool or maybe manufactured as a part of the downhole tool. The sensing component200 may also be modular in nature, and may be attached to theindependent mounting mechanism at a later time. For example, the sensingcomponent 200 may implement numerous sensors that each may be attachedseparately to a mounting mechanism.

Still further, the sensing component 200 may be attached to the downholetool 202 by other attachment or mounting means. For example, the sensingcomponent 200 could be attached to the downhole tool 200 by aspring-loading mounting mechanism. The spring-loading mounting mechanismmay implement a collar with one or more springs that allows the sensingcomponent 200 to be attached to downhole tools varying in diameter. Inaddition, the sensing component 200 may be attached to downhole toolswith straps or magnetic components that can be placed around theexterior of the downhole tool 202.

In some examples, the sensing component 200 may also implement awireless antenna 236. The wireless antenna 236 is shown mounted to theexterior housing 228, in this particular example. However, the wirelessantenna 236 may be placed adjacent to any location on the sensingcomponent 200 where the wireless antenna 236 is able to transmitwireless signal data. In some examples, the sensing component 200 maynot implement a wireless antenna 236 at all, but instead may implementother wireless technology, such as short range or long range wirelesscommunication.

The sensing component 200 may also implement one or more imaging sensorbackplates 250, 252. The imaging sensor backplates 250, 252 may includea transparent panel, such as a glass or plastic plate, that may behinged to allow for opening and closing. The imaging sensor backplates250, 252 may be placed over one or more control panels operable tocontrol the imaging sensors 204, 206. The control panel(s) may includemanual control components such as a thumbpad. The control panel(s) maybe used for manual control of the imaging sensors 204, 206 shouldwireless control become disabled or unavailable. For example, eachcontrol panel may be used to activate wireless components, powercomponents, etc. of the imaging sensors 204, 206. In addition, theimaging sensor backplates 250, 252 may implement one or more backplatefasteners 238, 240, 242, 244, 246, 248. The backplate fasteners 238,240, 242, 244, 246, 248 may be configured to secure the imaging sensorbackplates 250, 252 in a closed position, or allow the imagingbackplates 250, 252 to be moved to an open position.

In further examples, the sensing component may implement one or moreprotective lenses 254, 256. The protective lenses 254, 256 may beconfigured to attach over a surface of the imaging sensors 204, 206 toprevent foreign substances, such as water or oil, from penetrating theimaging sensors 204, 206. The protective lenses 254, 256 may include anacrylic glass panel, but other materials may be used depending on thedrilling environment, the product being produced, the imaging componentbeing protected, and other considerations.

In some instances, the sensing component may implement a rotatablehandle 258. The rotatable handle 258 may be configured to spin freely ona threading system to secure the mounting mechanism to the downhole tool202, or allow the removal of the mounting mechanism. The rotatablehandle 258 may enable the tightening and loosening of the mountingmechanism. In particular, the rotatable handle 258 may close or open theconnecting brackets 224, 226 for attachment and removal, respectively,of the sensing component 200 to the downhole tool 202. The rotatablehandle 258 may be permanently fixed to the sensing component 200 or maybe detachable, dependent on the sensing component 200 configuration. Inother examples, another suitable fastening component may be used in lieuof the rotatable handle 258.

The exact number and arrangement of the sensing component 200 componentsdescribed above may vary according to the specific angular offsetapparatus, drilling rig configuration, and other considerations. Forexample, in the illustrated example, the sensing component 200implements two imaging sensors 204, 206 and thus implements fourmounting brackets 216, 218, 220, 222, located at opposite ends of theimaging sensors 204, 206. In other examples, the sensing component mayimplement one imaging sensors, rotatable around the exterior of thedownhole tool 202, to allow for a 360-degree image, and may implementonly one mounting bracket, as described below with regard to theembodiment of FIG. 10. Or, the sensing component may implement someother plurality (e.g., three, four, eight, twenty, etc.) of imagingsensors, which can be stationary or rotatable, which may result in adifferent configuration of mounting bracket(s). Thus, since othersensing component 200 configurations may implement a different number ofsensors or the sensors may have a different arrangement, variedcomponents may be implemented.

Note that the design and implementation of the angular offset apparatusshown in FIG. 2 is not a limiting embodiment. Other designs may beconsidered and implemented according to the environment, requirement,and design considerations described herein.

FIG. 3 illustrates a first perspective view of the sensing component ofFIG. 2. In the illustrated example, one of the imaging backplates 250 isshown in an open configuration and the other imaging backplate 252 shownin a closed configuration. The open configuration of imaging backplate250 shows the backplate fasteners 238, 240, 242 in an unfastened, orloosened, position, allowing the imaging backplate 250 to be opened toexpose a control panel. The control panel allows manual control of theimaging sensor 204 if remote control is disabled or unavailable. Theclosed configuration of imaging backplate 252 shows the backplatefasteners 244, 246, 248 in the fastened, or tightened, position,ensuring that the imaging backplate 252 remains in the closed position.When the imaging backplate 252 is in the closed position, the controlpanel of the imaging sensor 206 is not exposed to the rig environmentand manipulation of or damage to the control panel is minimized.

In other examples, other materials and structures may be used forplacement over the control panel(s). For example, the imaging backplates250, 252 may be fixed in the closed position and controlled wirelessly.In some examples, a larger or smaller component may be placed over thecontrol panel(s). In further examples, the imaging backplates 250, 252may include high compressive strength and tensile resistant materials.

FIG. 4A illustrates a second perspective view of the sensing component200 of FIG. 2 in an unlatched configuration. In the illustrated example,the rotatable handle 258 is rotated to allow the mounting mechanism tobe in the unlatched configuration. The unlatched configuration allowsfor the connecting brackets 224, 226 to be expanded open and for thesensing component 200 to be removed from the downhole tool 202. When theconnecting brackets 224, 226 are in the opened/unlatched configuration,they are able to receive the downhole tool 202.

FIG. 4B illustrates a third perspective view of the sensing component ofFIG. 2 in a latched configuration. In this example, the rotatable handle258 is rotated to allow the mounting mechanism to be in the latchedconfiguration. The latched configuration allows for the connectingbrackets 224, 226 to be rotated to a closed position and for the sensingcomponent 200 to be securely mounted to the downhole tool 202.

For example, the mounting mechanism may implement a sensing componentlatching mechanism 404 located adjacent to the rotatable handle 258 andoperable by way of the rotatable handle 258. For example, the latchingmechanism may include a threaded bolting system that is loosened ortightened, or opened or closed, by way of the rotatable handle 258. Inother examples, other latching mechanisms may be used such as magnets,brackets, straps, etc.

In addition, in FIGS. 4A and 4B, at least one of the connecting brackets224, 226 may implement an indicator. For example, in the illustratedexamples, connecting bracket 252 implements an arrow 402. The arrow 402,may be utilized to indicate a location of interest. In one example, thearrow 402 may indicate the location of a high-side marking of thedownhole tool 202. The arrow 402, enables the sensing component 200 tobe aligned with the high-side marking. The alignment of the arrow 402with the high-side marking may be manual or automated. For example, thearrow 402 may be placed adjacent to the high-side marking by a rigemployee.

In some examples, one of the imaging sensors 204, 206 may be alignedwith the arrow 402, to serve as an origin point for the SLOcalculations. In other examples, the imaging sensors 204, 206 may belocated at other locations along the connecting brackets 224, 226 orwithin the rig environment. In these examples, the connecting brackets224, 226 may also include one or more indicators that represent a unitof measurement, such as an angular increment, that can be used todetermine the offset between the imaging sensors 204, 206 and the arrow402. The offset between the imaging sensors 204, 206 and the arrow 402,indicating the high-side marking of the downhole tool 202, may then beaccounted for in the SLO calculation.

In other examples, the sensing component 200 may implement one or morealignment sensors that can help determine if the arrow 402 is alignedwith the high-side marking. In one instance, the alignment sensor(s) maycollect image data of the placement of the sensing component 200 at thedownhole tool 202. In this example, the alignment sensor(s) may belocated on the top surface or bottom surface of the sensing component200, or placed adjacent to the inner portion of the sensing component200. The image data may be processed to verify whether the sensingcomponent 200 is aligned with a high-side marking of the downhole tool202. In the case of improper alignment, the sensing component 200 may bemanually re-aligned. Alternatively, the image data may be analyzed and,along with an electronic alignment mechanism, may allow for an automatedre-alignment of the sensing component 200 or manual re-alignment, via anonsite employee or a remote device operated by an offsite employee, toalign the sensing component with the high-side marking of the downholetool 202. For instance, one of the sensors 204, 206 or the arrow 402 ofthe sensing component 200 may be aligned with the high-side marking ofthe downhole tool 202.

FIG. 5A illustrates an example drilling assembly implementing a targetcomponent 500 of an angular offset apparatus according to some examples.In the illustrated example, the target component 500 includes a collar502, a target component latching mechanism 504, and a hinge mechanism506. The target component 500 is shown mounted at the directional tool508, located above a sensing component 510 mounted at a downhole tool512. However, in other embodiments, the target component 500 may belocated below the sensing component 510 or elsewhere on the rig,depending on the rig configuration.

In some examples, the hinge mechanism 506 of the target component 500 isconfigured to allow the target component 500 to open when the targetcomponent latching mechanism 504 is unsecured. For instance, when thetarget component latching mechanism 504 is in the unsecuredconfiguration, the target component 500 may hinge at the hingingmechanism 506 to create an opening in, or separation of, the targetcomponent to allow for placement or removal of the target component 500.The opening allows for the target component 500 to be placed around theouter diameter of the directional tool 508.

Once the target component 500 is placed around the directional tool 508,the target component 500 is aligned with the directional tool high-sidemarking 514. Once aligned, the target component 500 may hinge to theclosed position and secured in place with the target component latchingmechanism 504. The target component 500 may also be secured in placeadjacent to the directional tool 508 by other attachment mechanisms suchas magnets, straps, a bolting mechanism, etc.

In this example, the target component 500 is manually aligned with thedirectional tool high-side marking 514. However, in other examples, thetarget component 500 may be remotely and/or automatically aligned. Forexample, the target component 500 may include one or more sensors, suchas imaging sensors, that may collect image data associated with theplacement of the target component 500. The image data may be analyzedand used for aligning the target component 500 automatically and/orremotely. For instance, a unique marking of the target component may bealigned with the directional tool high-side marking 514 automaticallyand/or remotely.

In some examples, the target component 500 may also include one or moremarkings 516 on a surface of the target component 500 visible to thesensing component 510. The marking(s) 516 may indicate a pre-determinedvalue that can be used to calculate the scribe line offset (SLO) betweenthe downhole tool high-side marking 518 and the directional toolhigh-side marking 514. For example, each marking of the marking(s) 516may represent a certain degree increment of the 360 degrees of thetarget component 500. The downhole tool high-side marking 518 may serveas the origin point for the SLO calculation. The SLO may be calculatedby measuring the marking(s) 516, representative of a certain degreevalue, defining the offset between the downhole tool high-side marking518 and the directional tool high side marking 514.

In other examples, the high-side markings 514, 518 may be implemented asany identifying component. For example, the high-side markings 514, 518may include an identifier of any shape, size, and material, such as anarrow or lighted indicator. In addition, the high-side markings 514, 518may include a separate identifier that can be placed on a drilling toolat any time to indicate the high-side of the tool.

FIG. 5B illustrates a perspective view of the bottom surface of thetarget component 500 of FIG. 5A. The target component 500 includes thecollar 502, the target component latching mechanism 504, and the hingemechanism 506. The target component 500 also includes marking(s) 516,representative of a pre-determined degree value, used to calculated theSLO between the directional tool high-side marking 514 and the downholetool high-side marking 518.

While degree values are used in the illustrated example, any form ofmeasurement may be used in conjunction with the marking(s) 516 and,subsequently, the SLO. For example, units of length, diameter, innerdiameter, etc. may be used to divide and mark the target component 500into pre-determined units measurable to determine the SLO between thedirectional tool high-side marking 514 and the downhole tool high-sidemarking 518.

FIG. 5C illustrates another perspective view of a bottom surface of thetarget component 500 of FIG. 5A. The target component 500 includes oneor more markings 516 indicating a degree value of the 360 degrees of thetarget component 500. The marking(s) 516 may also have labeled referencepoints, which are indicated by the letters “A-H” in the illustratedexample. However, any labels may be used.

In this example, the target component 500 further implements a lasercomponent (not shown) that emits a light beam 520. The light beam 520indicates the location of the directional tool high-side marking 514.The light beam 520 may ensure proper alignment between the targetcomponent 500 and the directional tool high-side marking 514. Forexample, the light beam 520 may also be detected by one or more sensingcomponents located on the sensing component 510. The sensing componentdata may be analyzed to ensure that the light beam 520 is aligned withthe directional tool high-side marking 514. Proper alignment maximizesaccuracy for calculating the SLO between the directional tool 508 andthe downhole tool 512.

In other examples, the target component 500 may implement othercomponents to indicate the directional tool high-side marking 514. Forexample, the target component 500 may implement a unique marking, suchas a marking with a cross-hair, an LED light, or any other marking orindicator visible to the sensing component 510 and able to be detectedby the sensor(s) of the sensing component 510.

FIG. 6 illustrates a perspective view of an example drilling assemblyimplementing another embodiment of an angular offset apparatus 600. Inthe illustrated example, the angular offset apparatus 600 includes acollar component 602 and a marking component 604. The collar component602 may include a mounting mechanism 606 and one or more lightprojecting components 608. The marking component 604 may include one ormore sensor(s) 610.

In some examples, the collar component 602 may implement a mountingmechanism 606 that includes one or more spring-loaded mountingmechanisms located on the inner diameter of the collar component 602.The spring-loaded mounting mechanisms may expand and contract to allowmounting of the collar component 602 to drilling tools of varieddiameters and configurations. The collar component 602 may alsoimplement one or more light projecting components 608 located on abottom surface of the collar component 602. For example, the collarcomponent 602 may implement one or more lasers configured to projectlight in a downward direction towards the marking component 604.

The marking component 604 may implement one or more sensor(s) 610configured to detect light projected from the light projectingcomponent(s) 608 and collect associated light data. For example, themarking component 604 may implement one or more sensor(s) 610 alignedwith the high-side marking of the downhole tool 612 to indicate thehigh-side marking. The collar component 602 may be mounted at ahigh-side marking (not shown) of the directional tool 614, with at leastone light projecting component directly aligned with the high-sidemarking of the directional tool 614 at the start of a rotation, and thusbeing used as the light projecting origin point.

In some examples, to calculate the angular offset, or SLO, the collarcomponent 602 may rotate about the drilling assembly, at a fixedlocation, and the sensor(s) 610 may be configured to detect when thelight projecting component(s) 608 pass the sensor(s) 610 and collectlight data associated with the detection. The light data may betransmitted, either via wired or wireless technology, to a computingdevice 616 for processing. The light data may be analyzed to determineat what degree of rotation of the collar component 602 the sensor(s) 610detected the light from the light projecting component(s) 608. From thisanalyzed light data, along with the known light projecting origin point,the SLO may be calculated for use in directional drilling operations.

In further examples, the collar component 602 may be fixed and themarking component 604 may rotate. For example, the collar component 602may have one or more light projecting components 608 fixed at thehigh-side marking of the directional tool 614. The marking component 604may rotate about the downhole tool 612 and the sensor(s) 610 may collectdata including when the sensor(s) 610 detect light projected from thelight projecting component(s) 608. The marking component 604 may includeone or more sensor(s) 610 aligned with the high-side of the downholetool 612 at the start of rotation, serving as the known sensor originpoint. In some examples, the rotation may take place by way of a bearingsystem, magnetic tracks, a gear and motor unit, or automatically viaother mechanical means.

The collected data may be transmitted, either via wired or wirelesstechnology, to a computing device 616 for processing. The data may beanalyzed to determine at what degree of rotation the sensor(s) 610 ofthe marking component 604 detected light emitted from the lightprojecting component(s) 608. From this analyzed light data, along withthe known sensor origin point, the SLO may be calculated.

In the illustrated example, the collar component 602 is mounted on adirectional tool 614 and the marking component 604 is mounted on adownhole tool 612. However, in some embodiments, the collar component602 and the downhole tool 612 may be mounted at different locations,depending on weight requirements, safety considerations, the rigenvironment and tooling, and other considerations. For example, thecollar component 602 may be mounted at the downhole tool 612 and themarking component 604 may be mounted at the directional tool 614.

In other examples, the sensor(s) 610 may be replaced with reflectivesurfaces, such as mirrors or any other material with a mirror finish,that are able to reflect light from the light projecting component(s)608 back towards the collar component 602. In this example, the collarcomponent 602 may implement one or more sensors able to detect lightfrom the light projecting component(s) 608 to calculate the SLO. Inaddition, the collar component 602 may also implement other componentssuch as a protective housing.

FIG. 7 illustrates an example architecture of a control system 700 thatcan include one or more computing devices. In some cases, the controlsystem 700 can include the computing device 108 of FIG. 1. The computingdevice may include, for example, a mobile phone, a tablet, a laptopcomputer, a desktop computer, an electronic notepad, a server computingdevice, etc. In additional implementations, the control system 700 canbe implemented in a cloud-computing architecture. The control system700, collectively comprises processing resources, as represented byprocessor(s) 702, input/output device(s) 704, communication interface(s)706, and one or more computer-readable storage media 708.

Processor(s) 702 can represent, for example, a CPU-type processing unit,a GPU-type processing unit, a Field-Programmable Gate Array (FPGA),another class of Digital Signal Processor (DSP), or other hardware logiccomponents that can, in some instances, be driven by a CPU. For example,and without limitation, illustrative types of hardware logic componentsthat can be used include Application-Specific Integrated Circuits(ASICs), Application-Specific Standard Products (ASSPs),System-on-a-Chip Systems (SOCs), Complex Programmable Logic Devices(CPLDs), etc. In at least one example, an accelerator can represent ahybrid device, such as one from ZYLEX or ALTERA that includes a CPUcourse embedded in an FPGA fabric. In various embodiments, theprocessor(s) 702 can execute one or more modules and/or processes tocause computing device(s) to perform a variety of functionalities, asset forth above and explained in further detail in the followingdisclosure. Additionally, each of the processor(s) 702 can possess itsown local memory, which also can store program modules, program data,and/or one or more operating systems.

The computer-readable storage media 708 may include volatile andnonvolatile memory, removable and non-removable media implemented in anymethod or technology for storage of information, such ascomputer-readable instructions, data structures, program modules, orother data. Such memory includes, but is not limited to, RAM, ROM,EEPROM, flash memory or other memory technology, CD-ROM, digitalversatile disks (DVD) or other optical storage, magnetic cassettes,magnetic tape, magnetic disk storage or other magnetic storage devices,RAID storage systems, or any other medium which can be used to store thedesired information and which can be accessed by a computing device.

Several modules such as instruction, data stores, and so forth may alsobe stored within the one or more computer-readable media 708 andconfigured to execute on the processor(s) 702. For example, the one ormore computer-readable media 708 may store a sensor data receiving andprocessing module 710, a directional tool high-side determination module712, a downhole tool high-side determination module 714, a scribe lineoffset (SLO) determination module 716, and a graphical user interface(GUI) generation/presentation module 718. The one or morecomputer-readable media 708 may also store data, such as targetcomponent marking data 720, that includes data related to markings onthe target component such as the unit of measurement, increment value,etc.

In some examples, the sensor data receiving and processing module 710 isconfigured to receive and process sensor data from a sensing component,such as the sensing component 104 of FIG. 1. For example, the sensors110, 112 of the sensing component 104 may collect image data that istransmitted to the control system 700 via wired or wireless means. Thesensor data receiving and processing module 710 may receive the imagedata and process the data. Processing the data may include parsing theimage data for quality, compiling a number of images into a compositeimage, dimensional analysis, mechanical analysis, nondestructivetesting, nondestructive evaluation, maintenance analysis, fatigue andfailure analysis, etc. Further, each image or composite image may bemarked with a unique serial number and/or other identificationinformation, such as information related to the equipment in the rigenvironment. Marked images may be stored for subsequent recall.Identifying and storing each rendered image helps keep a running log ofeach image used to calculate each SLO for accountability and use by therig crew. Storage may take place on a server system, cloud-based storageplatforms, or other storage applications.

In further examples, the directional tool high-side determination module712 may use the composite image to determine the location of thehigh-side marking of the directional tool 114. For example, thedirectional tool high-side determination module 712 may use image datafrom the sensing component 104 showing the high-side marking of thedirectional tool 114, or an indicator located on the target component106, to determine the location of the high-side of the directional tool114. In some examples, various alignment mechanisms may be used, as wellas user selections, to ensure the proper determination of the high-sidemarking of the directional tool 114. For example, a user may selectvarious boundary points, in a graphical user interface, to align thecomposite image with an overlay image or axis to determine the correctlocation of the high-side marking of the directional tool 114.

The downhole tool high-side determination module 714 may use thecomposite image to determine the location of the high-side marking ofthe downhole tool 116. For example, one of the sensors of the sensingcomponent 104 may be aligned with the high-side marking of the downholetool 116. Thus, the location is determined by analyzing the image datafrom the sensing component 104 aligned with the high-side marking of thedownhole tool 116, where a horizontal axis of the image is thereforealigned with the high-side marking of the downhole tool 116. In otherexamples, various sensors may collect data from the inner diameter ofthe sensing component 104 to determine the location of the high-sidemarking of the downhole tool 116. For instance, one or more imagingsensors, such as cameras, may be placed in a way to allow collection ofimage data of the exterior of the downhole tool 116. In still furtherexamples, the sensing component 104 may have an indicator aligned withthe high-side marking of the downhole tool 116. Sensor data associatedwith the indicator may be used to determine the location of thehigh-side marking of the downhole tool 116 or the offset between theindicator and the sensors of the sensing component 104. For instance,one or more imaging components may be configured to collect image dataof the location of the indicator.

The scribe line offset determination module 716 may then use thedetermined directional tool high-side marking location and the downholetool high-side marking location to determine the SLO, or angular offsetbetween the high-sides of the directional tool 114 and the downhole tool116. The SLO may be determined using trigonometric functions andanalysis, in some examples.

The graphical user interface (GUI) generation/presentation module 718may generate and cause the presentation of graphical user interface(s).For example, the GUI generation/presentation module 718 may generate andcause the presentation of the graphical user interface(s) describe belowwith reference to FIGS. 8A-C.

As noted above, the control system 700 may include one or more input oroutput devices. The input/output device(s) 704 may include one or moreuser display screens that enable a user to select at least a portion ofan image that is used by the sensor data receiving and processing module710, directional tool high-side determination module 712, downhole toolhigh-side determination module 714, and scribe line offset determinationmodule 716 to calculate the SLO. Examples of the various input/outputdevice(s) 704 are described in greater detail with respect to FIGS. 8A-Cbelow.

In addition, in some examples the control system 700 may also includeone or more communication interfaces 706, which may support both wiredand wireless connection to various networks, such as cellular networks,radio, short range or long range wireless communication networks,shortrange or near-field networks (e.g., Bluetooth®), infrared signals,local area networks, wide area networks, the Internet, and so forth. Forexample, the communication interface(s) 706 may allow the computingdevice 700 to provide the SLO determined by the scribe line offsetdetermination module 716 to the directional tool 114.

FIGS. 8A-C illustrate various graphical user interface examples 800,802, 804 that can be presented via the input/output device(s) 704 asdescribed above with reference to FIG. 7. The graphical user interfaceexamples 800, 802, 804 include graphical user interfaces displayed to auser to allow the user to interact with the image data collected by thesensors 110, 112 of the sensing component 104. Once the necessary imagedata has been selected, the scribe line offset (SLO) may be calculated.

FIG. 8A illustrates the first graphical user interface 800. In someexamples, the first graphical user interface 800, which may be presentedvia the input/output device(s) 704 of a computing device, such as adisplay of computing device 108, may allow for selection of a primaryimage. The primary image may include image data collected by either, orboth, of the sensors 110, 112, described above with reference to FIG. 1.The first graphical user interface 800 may include a browsing optionthat allows the user to browse from among all of the image data that hasbeen collected from the sensors 110, 112.

FIG. 8B illustrates the second graphical user interface 802. The secondgraphical user interface 802, which may be presented via theinput/output device(s) 704 of a computing device, such as the displaycomputing device 108, may allow for selection of a secondary image. Thesecondary image may include image data collected by either, or both, ofthe sensors 110, 112. For example, if the user has selected image datacollected by the first sensor 110 as the primary image, the user mayselect image data collected by the second sensor 112 as the secondaryimage. Including a primary image collected by the first sensor 110 and asecondary image collected by the second sensor 112 allows the computingdevice 108 to render a composite image. In some cases, the compositeimage can include a 360-degree view of the target component 106. Inother examples, the user may choose from among various composite imagespreviously rendered. The first graphical user interface 800 may includea browsing option that allows the user to browse from among the imagedata that has been collected from the sensors 110, 112. The primaryimage or the secondary image, or both, may include the image datashowing the high-side marking of the directional tool 116.

FIG. 8C illustrates the third graphical user interface 804. The thirdgraphical user interface 804, which may be presented via theinput/output device(s) 704 of a computing device, such as the display ofcomputing device 108, may allow for a user to position certain referencepoints to align the image with the interface overlay 806. In thisexample, the interface overlay 806 includes a horizontal line 808 and aperpendicular line 810 that intersect, along with a dashed circle 812.The interface overlay 806 may enable a user to align the interfaceoverlay 806 with image data to determine a SLO. The interface overlay806 may be configured according to the design of the sensing component104 and the target component 106. For instance, the sensing component104 and the target component 106 may be designed to place the downholetool 116 and the directional tool 114 in the center of and parallel tothe sensing component 104 and the center of and parallel to the targetcomponent 106, respectively. This design allows for alignment of theinterface overlay 806 with the image data.

In some examples, the interface overlay 806 also includes two solid dots814, 816 and one diamond marking 818 that help align the dashed circle812 with the target component image 820, previously selected as theprimary image in graphical user interface 800. In this example, thetarget component image 820 includes markings of the letters “A” through“H,” with each letter representing a certain increment of the 360-degreecircle.

The two solid dots 814, 816 may be placed adjacent to two outer diameterlocations of the target component 106 shown in the target componentimage 820. The placement of the two solid dots 814, 816 helps align thedashed circle 812 of the interface overlay 806 with the target component106 in the target component image 820. The alignment of the targetcomponent and the dashed circle helps set the bounds of the 360-degreecircle of the target component and the dashed circle 812. The diamondmarking 818 is aligned with a third boundary of the target component ofthe target component image 820 and helps further set the bounds of the360-degree circle of the target component and the dashed circle 812.

In some examples, an open circle 824 is located at the intersection ofthe horizontal line 808 and a perpendicular line 810. This intersectionis aligned with the center of the sensing component drilling tool, suchas the downhole tool 116, which the sensing component 104 is attachedto, which may further be aligned with the high-side marking. Ahorizontal axis reference point 822, represented by an open dashedcircle, is also placed at the bounds of the dashed circle 812 along thehorizontal axis. This horizontal axis reference point 822 is representedby a patterned circle and represents the location of the high-sidemarking of the sensing component drilling tool, such as the downholetool 116, to which the sensing component is attached.

Next, in some examples, the user may then select a calculation point.The calculation point is identified on the graphical user interface 804by the diamond marking 818. To determine the scribe line offset (SLO),the chosen calculation point, indicated by the diamond marking 818, isfirst identified. Next, the location of the target component drillingtool high-side marking, such as the directional tool 114, is determinedwith reference to the markings. While the location of the high-sidemarking may be known from the image data collected by the sensingcomponent 104, the location of the target component drilling toolhigh-side marking with reference to the markings “A” through “H” may notbe known or may not be visible in the chosen primary image.

In this illustration, the chosen calculation point is represented by theletter “G.” The target component drilling tool high-side marking isknown to be at a position located at position “A,” however the labelassociated with the high-side marking may not be known. Since theunmarked location of the target component high-side marking is known,along with the increment or unit associated with each marking, thechosen calculation point “G” can be used to determine that the targetcomponent high-side marking is positioned at marking “A.”

To determine that the target component high-side marking is located atmarking “A,” the angular offset between the chosen marking point “G” andthe target component high-side marking point “A” 826 is determined. Forexample, if the target component high-side marking is known to belocated 90 degrees clockwise from the marking “G,” and each marking“A-H” is known to represent 45 degrees, the system can deduce that thetarget component marking is located two markings from “G” at marking“A.” Once the target component high-side marking reference point “A” 826is known, along with the horizontal access reference point 822,representing the location of high-side marking of the sensing componentdrilling tool, the SLO between the target component drilling toolhigh-side marking and the sensing component drilling tool high-sidemarking is determined.

FIG. 9 illustrates an example flow diagram showing an illustrativeprocess for determining a scribe line offset (SLO), or angular offset,using the angular offset apparatus 102 of FIG. 1 and the control system700 of FIG. 7. The processes are illustrated as a collection of blocksin a logical flow diagram, which represent a sequence of operations,some or all of which can be implemented in hardware, software or acombination thereof. In the context of software, the blocks representcomputer-executable instructions stored on one or more computer-readablemedia that, which when executed by one or more processors, perform therecited operations. Generally, computer-executable instructions includeroutines, programs, objects, components, data structures and the likethat perform particular functions or implement particular abstract datatypes. Also, a computing device is part of a system having multiplecomputing devices in communication with each other and/or one or morecloud services.

The order in which the operations are described should not be construedas a limitation. Any number of the described blocks can be combined inany order and/or in parallel to implement the process, or alternativeprocesses, and not all of the blocks need be executed. For discussionpurposes, the processes herein are described with reference to theframeworks, architectures and environments described in the examplesherein, although the processes may be implemented in a wide variety ofother frameworks, architectures, or environments.

As noted above, FIG. 9 illustrates an example flow diagram 900illustrating example processes for determining a scribe line offset(SLO), or angular offset, using the angular offset apparatus 102 ofFIG. 1. For example, as discussed above, a sensing component 104, atarget component 106, and a computing device 108 may be used todetermine the SLO of a rig environment. The computing device mayimplement a control system such as the control system 700 describedabove with respect to FIG. 7.

At operation 902, the sensor data is received. For example, the sensordata may be received by the control system 700 of the computing device108. In this example, the sensor data receiving and processing module710 of control system 700 may receive the sensor data for processing. Insome instances, the sensor data is transmitted, either wirelessly or viaa wired configuration, to the control system 700. For example, the oneor more sensors of a sensing component may implement a wireless antenna,such as the wireless antenna described above with reference to FIG. 2,that is able to transmit the sensor data to the control system 700 ofthe computing device 108. In other examples, the one or more sensors maybe hard-wired to an external device to transmit the sensing data to thecomputing device 108. In further examples, any long range or short rangewireless communication methods may be used.

In some instances, the received sensor data is collected via one or moresensors, such as sensors 110, 112 of the sensing component 104 describedabove. For instance, the sensors 110, 112 may include imaging sensorsconfigured to collect image data of the target component 106. In otherinstances, the sensor data may include sensor data related to localpositioning, heat, light (i.e., including electromagnetic radiation ofany frequency), etc. For example, the one or more sensors may bedesigned to detect light from the target component 106, such as fromlasers that are included in an example target component. Additionaland/or alternative examples include one or more sensors configured todetect indicator(s) produced via non-visible light.

At operation 904, the sensor data is processed. The sensor data isprocessed, for example, by the sensor data receiving and processingmodule 710. For instance, the sensor data receiving and processingmodule 710 may process the image data collected by sensors 110, 112 ofthe sensing component 104, and may produce a composite image foranalysis by the other modules of the control system 700. As anotherexample, the sensor data may be received from light detecting sensorssuch as the sensor(s) 610, described in FIG. 6, configured to detectfrom the light projecting component(s) 608, is processed.

At operation 906, the marking data is accessed. For instance, the targetcomponent marking data 720 may be accessed to retrieve previously storeddata regarding the unit of measurement represented by each marking, theincrement value of each marking, the marking labels, etc. In someexamples, such as when implementing a local positioning system, themarking data may include the known location of the beacon or antenna. Instill further examples, the marking data may include the known locationthat a sensor or marking/indicator component is placed at along thedownhole tool or directional tool, such as a high-side marking locationthat has been stored in the control system 700.

At operation 908, the high-side location of the directional tool isdetermined. For example, the high-side location of the directional tool114 is determined. For instance, the directional tool high-sidedetermination module 712 may analyze the composite image to determinethe location of the high-side marking of the directional tool 114 thatthe target component 106 is aligned with. As described above, thealignment of the target component 106 with the high-side marking of thedirectional tool 114 may be indicated in a number of ways, including aunique marking, an LED light, a laser beam, etc. that is shown in thecomposite image. Other methods for determining the location of thehigh-side marking of the directional tool 114 are also described abovewith respect to FIGS. 8A-C.

In other examples, the directional tool high-side determination module712 may analyze local positioning data from one or more localpositioning antennas or beacons. As described above, the location of thehigh-side marking of a directional tool may be determined byestablishing a grid system (e.g. placing one or more local positioningcomponents in an environment), placing an antenna or beacon at thedirectional tool, and measuring the time period needed for a ping fromthe antenna or beacon to travel to the local positioning component andthe time period needed for the ping to travel back to the antenna orbeacon. The directional tool high-side determination module 712 may thenuse the measured time periods, along with the known location/placementinformation of the antenna or beacon accessed at operation 910, todetermine the location of the high-side of the directional tool. Instill further examples, the location of the high-side of the directionaltool may be known from the marking data that is accessed at operation906.

At operation 910, the high-side location of the downhole tool isdetermined. For example, the downhole tool high-side determinationmodule 714 may be used to determine the high-side location of thedownhole tool. For instance, at least one sensor of the sensors 110, 112of the sensing component 106 may be aligned with the high-side markingof the downhole tool 116 at a known location, serving as the originlocation. The origin location data may be pre-programmed into thesensing component 106 and transmitted to the control system 700. Inalternative examples, sensors may be located along the inner surface ofthe sensing component 106 that may be used to determine the location ofthe high-side marking of the downhole tool 116. In still furtherexamples, markings along the sensing component 106 may help determine anoffset between the high-side marking of the downhole tool 116 and thesensor. Other methods for determining the location of the high-sidemarking of the downhole tool 116 by utilizing input from a user via agraphical user interface are also described above with respect to FIGS.8A-C.

In other examples, the downhole tool high-side determination module 714may analyze local positioning data from one or more local positioningantennas or beacons. As described above, the location of the high-sidemarking of a downhole tool may be determined by establishing a gridsystem (e.g. placing one or more local positioning components in anenvironment), placing an antenna or beacon at the downhole tool, andmeasuring the time period needed for a ping from the antenna or beaconto travel to the local positioning component and the time period neededfor the ping to travel back to the antenna or beacon. The downhole toolhigh-side determination module 714 may then use the measured timeperiods, along with the known location/placement information of theantenna or beacon, to determine the location of the high-side of thedownhole tool.

At operation 912, the SLO is determined. The SLO is determined, forexample, by the scribe line offset determination module 716. Forinstance, once the location of the high-sides of the directional tooland the downhole tool are known, as well as the target component markingdata, the scribe line offset determination module 716 may determine theSLO, or angular offset, between the high-side of the directional tooland the high-side of the downhole tool. In some examples, a user mayutilize the marking data to help determine the SLO. For example, theuser may pick reference points, or markings, to be used to calculate theSLO as described above with respect to FIGS. 8A-H. At operation 914, theSLO may be provided to the user and the directional tool via thecommunication interface(s) 704 for use in directional drillingoperations.

FIG. 10 illustrates a perspective view of another example sensingcomponent 1000 of the angular offset apparatus described herein. In thisexample, the sensing component 1000 implements one imaging sensor 1002placed at a downhole tool or drilling tool and configured to captureimage content. For example, the sensing component 1000 may be placed atan external high-side marking of a downhole tool or drilling tool of adrilling environment. The sensing component 1000 may rotate about thedownhole tool or drilling tool to capture sensor data associated withthe drilling environment.

In this example, the imaging sensor 1002 may be placed adjacent to anexternal high-side marking (not shown) of a downhole tool (not shown) atthe start of a rotation to help determine an approximate origin locationof the imaging sensor 1002. Knowing the origin location of the imagingsensor 1002 may help determine the scribe line offset (SLO) by providinginformation such as the location of the high-side marking of thedownhole tool (i.e. the origin of the offset of the rig) as well ashelping to set the aspect ratio of the image content or helping todetermine other significant values needed for the SLO calculation. Inother embodiments, the imaging sensor 1002 may be placed away from thehigh-side marking of the downhole tool. In some embodiments, the sensingcomponent 1000 itself may include a marking or indicator that may bealigned with an external high-side marking of a tool that may help alignthe imaging sensor 1002 with the external high-side marking at the startof the rotation.

In some examples, the image content may include image data, captured bythe imaging sensor 1002 during a rotation about the tool. For example,if the sensing component 1000 is placed adjacent to an externalhigh-side marking of a downhole tool (not shown), the image content mayinclude image data showing a marker or indication of the location of asecond high-side marking of another drilling tool, such as a directionaltool, of a bottom hole assembly (BHA). The location of the drilling toolhigh-side marking, along with the location of the downhole toolhigh-side marking, may be used to determine the SLO, sometimes referredto as the angular offset, of the two high-side markings with increasedprecision and accuracy.

In the illustrated example, the sensing component 1000 implements amounting mechanism 1004 that can be latched and unlatched for attachmentand removal, respectfully, of the sensing component 1000. The mountingmechanism may be similar in design to the mounting mechanism describeabove with respect to FIG. 2. For example, the mounting mechanism 1004may implement various components such as one or more attachmentfasteners 1006, 1008, one or more transport mechanisms 1010, 1012, oneor more mounting brackets 1014, 1016, and one or more connectingbrackets 1018, 1020, similar in design and function to those describedabove with respect to FIG. 2. The mounting mechanism 1004 may helpensure that that sensing component 1000, or a marking or indicator ofthe sensing component 1000, is aligned with the center line of thedownhole drilling tool, or other tool, when mounted.

The mounting mechanism may further implement a sensing componentlatching mechanism 1022. The latching mechanism 1022 may be locatedadjacent to a rotatable handle (not shown) and operable by way of therotatable handle. For example, the latching mechanism may include athreaded bolting system that is loosened or tightened, or opened orclosed, by way of the rotatable handle. In other examples, otherlatching mechanisms may be used such as magnets, brackets, straps, etc.The latching mechanism 1022 and rotatable handle may be similar indesign and function to those described above with respect to FIG. 2.

In some examples, the sensing component 1000 may further implement oneor more imaging sensor backplates (not shown), one or more backplatefasteners 1024, 1026, one or more protective lenses 1028, one or moreexterior housings 1030, and a wireless antenna (not shown) similar indesign and function to those described above with respect to FIG. 2. Thewireless antenna may be placed adjacent to any location on the sensingcomponent 1000 where the wireless antenna is able to transmit wirelesssignal data. In some examples, the sensing component 1000 may notimplement a wireless antenna at all, but instead may implement otherwireless technology, such as short range or long range wirelesscommunication.

In this example, the sensing component 1000 also implements a rotationassembly about which the imaging sensor 1002 rotates. For instance, inthe illustrated example, the sensing component 1000 implements a rollerbearing assembly 1032 allowing for the imaging sensor 1002 to rotate 180degrees about a tool. In other examples, other rotation assemblies maybe implemented, such as a magnetic rotation assembly, and the rotationassembly may be manually or automatically controlled, via othermechanical means.

For example, in FIG. 10, the embodiment shown is manually controlled andthe sensing component 1000 implements a release mechanism 1034. Therelease mechanism 1034 may include a handle. In some instances, when therelease mechanism 1034 is lifted the imaging sensor 1002 becomes mobileand may be manually rotated along the roller bearing assembly 1032. Inother instances, when the handle is lowered, or released from the liftedposition (as shown in FIG. 10), the imaging sensor 1002 becomesstationary and is not able to be rotated about the roller bearingassembly 1032. The release mechanism 1034 allows the imaging sensor 1002to be stationary in a desired position to capture image data. In otherexamples, the sensing component 1000 may be automatically controlled viamechanical means and may be controlled either locally or externally tothe sensing component 1000.

In some examples, the imaging sensor 1002 rotates about the rollerbearing assembly 1032 to capture image data of the drilling environment.The imaging sensor 1002 may capture image data in a continuous ornon-continuous manner while in rotation. For example, the imaging sensor1002 may capture image data continuously throughout the rotation aboutthe roller bearing assembly 1032. In other examples, the imaging sensor1002 may capture image data only at the beginning and end of therotation. For instance, the imaging sensor 1002 may capture image datawhile at a first end 1036 of the roller bearing assembly 1032 and whileat a second end 1038 of the roller bearing assembly 1032, resulting inimage data spaced 180 degrees apart. The first end 1036 of the rollerbearing assembly 1032 may include a marker or indicator that aligns withan external high-side marking of tool, such as a downhole tool ordrilling tool, to which the sensing component 1000 is attached.

The non-continuous image data may be processed and utilized forcalculating the SLO. During processing, image rendering may beperformed, an aspect ratio may be set, combined images may be generated,image recognition techniques may be applied, etc. For instance, theimage data captured at the beginning and end of the rotation, such as atfirst end 1036 of the roller bearing assembly 1032 and at the second end1038 of the roller bearing assembly 1032, may be combined to render a360 degree image of the drilling environment.

In addition, while the sensing component 1000 illustrated in FIG. 10 isremovable, alternative examples may include a sensing component 1000that is permanently attached to a drilling tool. Also, the sensingcomponent 1000 may not implement a mounting mechanism 1004 and may beattached to a tool via alternative attachment means. For example, othermounting mechanisms may be separate components, independent of thesensing component 1000, that may be attached to the desired tool or maybe manufactured as a part of the tool. The sensing component 1000 mayalso be modular in nature, and may be attached to an independentmounting mechanism at a later time.

Still further, the sensing component 1000 may be attached to a tool,such as a downhole tool, by other attachment or mounting means. Forexample, the sensing component 1000 could be attached to the downholetool by a spring-loading mounting mechanism. The spring-loading mountingmechanism may implement a collar with one or more springs that allowsthe sensing component 1000 to be attached to downhole tools varying indiameter. In addition, the sensing component 1000 may be attached todownhole tools with straps or magnetic components that can be placedaround the exterior of the downhole tool.

The exact number and arrangement of the sensing component 1000components described above may vary according to the specific angularoffset apparatus, drilling rig configuration, and other considerations.For example, in the illustrated example, the sensing component 1000implements one imaging sensor 1002 and thus implements two mountingbrackets 1014, 1016, located at opposite ends of the imaging sensor1002. In other examples, the sensing component may implement two imagingsensors, rotatable around the exterior of a tool, and may implement fourmounting brackets, as described above with respect to the embodiment ofFIG. 2. Or, the sensing component may implement some other plurality(e.g., six, ten, twenty, etc.) of imaging sensors, which can bestationary or rotatable, which may result in a different configurationof mounting bracket(s). Thus, since other sensing component 1000configurations may implement a different number of sensors, or thesensors may have a different arrangement, varied components may beimplemented.

Note that the design and implementation of the angular offset apparatusshown in FIG. 10 is not a limiting embodiment. Other designs may beconsidered and implemented according to the environment, requirement,and design considerations described herein.

Although the subject matter has been described in language specific tostructural features, it is to be understood that the subject matterdefined in the appended claims is not necessarily limited to thespecific features described. Rather, the specific features are disclosedas illustrative forms of implementing the claims.

What is claimed is:
 1. An angular offset tool comprising: a sensingcomponent, wherein the sensing component is located at a firstdirectional marking of a first drilling tool, the sensing componentincluding an image sensor configured to capture image data associatedwith a second directional marking of a second drilling tool, and whereinthe first drilling tool is disposed at a first position along a drillingassembly and the second drilling tool is disposed at a second positionalong the drilling assembly; a target component, wherein the targetcomponent is located at the second directional marking of the seconddrilling tool; and a computing system, the computing system configuredto calculate an angular offset between the first drilling tool and thesecond drilling tool, wherein calculating the angular offset includesanalyzing the image data to determine the angular offset.
 2. The angularoffset tool of claim 1, wherein the target component includes one ormore indicators comprising at least one of a light-emitting indicator, aheat-emitting indicator, a unique physical marking, or a localpositioning antenna.
 3. The angular offset tool of claim 2, wherein theone or more one or more indicators are aligned with the seconddirectional marking of the second drilling tool.
 4. The angular offsettool of claim 1, wherein the sensing component further includes anindicator aligned with the first directional marking of the firstdrilling tool.
 5. The angular offset tool of claim 1, wherein thesensing component further includes a transmission device to transmit theimage data to the computing system.
 6. The angular offset tool of claim2, wherein the sensing component further includes one or more sensorscomprising at least one of local positioning sensor or a heat sensor. 7.The angular offset tool of claim 1, wherein calculating the angularoffset between the first drilling tool and the second drilling toolcomprises: receiving the image data associated with the targetcomponent; determining a location of the first directional marking ofthe first drilling tool based at least in part on the image data;determining a location of the second directional marking of the seconddrilling tool based at least in part on the image data; and determiningthe angular offset between the location of the first directional markingof the first drilling tool and the location of the second directionalmarking of the second drilling tool.
 8. The angular offset tool of claim1, wherein the sensing component further includes a mounting mechanismto attach the sensing component to the first drilling tool.
 9. Theangular offset tool of claim 1, wherein the computing system isimplemented in one of an external computing device or is included in thesensing component.
 10. The angular offset tool of claim 1, wherein thefirst directional marking is a first high-side marking and the seconddirectional marking is a second high-side marking.
 11. A devicecomprising: one or more indicators, the one or more indicators locatedon a first drilling tool of a drilling assembly; one or more sensors,the one or more sensors including one or more image sensors located on asecond drilling tool of the drilling assembly to collect image dataassociated with the one or more indicators, wherein the first drillingtool is disposed at a first position along the drilling assembly and thesecond drilling tool is disposed at a second position along the drillingassembly; and a computing system, the computing system configured todetermine a relationship between the first drilling tool and the seconddrilling tool, wherein determining the relationship includes analyzingthe image data to determine an angular offset between the first drillingtool and the second drilling tool.
 12. The device of claim 11, whereinthe one or more indicators include at least one of a light-emittingindicator, a heat-emitting indicator, a unique physical marking, or alocal positioning antenna.
 13. The device of claim 12, wherein the oneor more indicators are aligned with at least one of a first directionalmarking of the first drilling tool or a second directional marking ofthe second drilling tool.
 14. The device of claim 13, whereindetermining the angular offset between the first drilling tool and thesecond drilling tool includes determining the angular offset between thefirst directional marking of the first drilling tool and the seconddirectional marking of the second drilling tool.
 15. A methodcomprising: receiving sensor data from a sensing component of an angularoffset tool, the sensor data including image data captured by an imagesensor of the sensing component and associated with a first heading of afirst drilling tool and a second heading of a second drilling tool,wherein the first drilling tool is disposed at a first position along adrilling assembly and the second drilling tool is disposed at a secondposition along the drilling assembly; based at least in part on theimage data, determining a first measurement associated with the firstheading of the first drilling tool; based at least in part on the imagedata, determining a second measurement associated with the secondheading of the second drilling tool; and determining an angular offsetbetween the first drilling tool and the second drilling tool.
 16. Themethod of claim 15, wherein the image data includes images associatedwith one or more indicators of a target component of the angular offsettool.
 17. The method of claim 16, wherein the one or more indicatorsinclude at least one of a light-emitting indicator, a heat-emittingindicator, a physical marking, or a local positioning antenna.
 18. Themethod of claim 15, wherein the first heading of the first drilling toolis indicated by a first directional marking and the second heading ofthe second drilling tool is indicated by a second directional marking.19. The method of claim of claim 18, wherein the image data includesimages associated with at least one of the first directional marking orthe second directional marking.